It is well known that large reservoirs of petroleum (e.g. heavy oil) are found in certain frigid areas of the world; e.g. the North Slope area of Alaska. As will be readily recognized, the extreme cold temperatures which normally exist in these areas significantly add to the problems involved in the economical production of these reservoirs. For example, one of the major costs involved in producing shallow, heavy oil reservoirs in frigid areas is that incurred in maintaining a suitable temperature within the production tubing so that the production fluids can readily flow or be pumped therethrough to the surface. This is especially vital for that portion of the production tubing which passes through the "permafrost" layer (i.e. permanently frozen layer) which is normally present in such frigid areas. If the temperature within the tubing drops too much, especially during low flow or no flow (i.e.shut-in) conditions, the well fluids cool off and can become too viscous to readily flow or to be pumped through the tubing. In some cases, the fluids may actually freeze solid within the tubing thereby creating a myriad of problems when the well is returned to full flow production.
Some of the more common approaches presently used in dealing with this problem include: (a) insulating the production tubing and/or the wellbore; (b) displacing the well fluids from the production tubing back into the wellbore and/or production formation with a non-freezing or anti-freeze fluid (e.g. methanol, diesel, or natural gas) during no-flow conditions; or (c) strapping an electrical, heat trace to the outside of the production tubing to heat the tubing and thereby maintain the temperature within the production tubing at an acceptable flow temperature. Unfortunately, while each of these techniques may be applicable to particular situations, each may have serious drawbacks in others.
For example, insulating the production tubing and/or the wellbore simply does not prevent freezing of the well fluids in the tubing but merely slows down the process. As to displacing the well fluids back out of the production tubing while production is shut-in, this process is normally expensive and labor intensive in that it must be carried out manually and can not be easily automated to "kick-in" only when needed. And finally, strapping the heat trace to the outside of the production tubing is grossly inefficient due to the amount of heat which is lost directly to the surrounding annulus in the wellbore and is unavailable for heating the inside of the production tubing. That is, a large portion of the heat generated by an externally-mounted heat trace is immediately lost in the well annulus and is never conveyed to the inside of the production tubing where it needed. Accordingly, it can be seen that a need continues to exist for automatically maintaining the temperature inside the production tubing of a well which extends through a permafrost layer at a desired temperature which allows ready flow of produced fluids therethrough, especially during low or no flow production rates.